Howard R. Hughes invented a drill bit with rolling cones used for drilling oil and gas wells, calling it a "rock bit" because it drilled from the outset with astonishing ease through the hard caprock that overlaid the producing formation in the Spindletop Field near Beaumont, Tex. His bit was an instant success, said by some the most important invention that made rotary drilling for oil and gas commercially feasible the world over (U.S. Pat. No. 930,759, "Drill," Aug. 10, 1909). More than any other, this invention transformed the economies of Texas and the United States into energy-producing giants. But his invention was not perfect.
While Mr. Hughes' bit demolished rock with impressive speed, it struggled in the soft formations such as the shales around Beaumont and in the Gulf Coast of the United States. Shale cuttings sometimes compacted between the teeth of the "Hughes" bit until it could no longer penetrate the earth. When pulled to the surface, the bit was often, as the drillers said, "balled up" with shale--sometimes until the cutters could no longer turn. Even moderate balling up slowed the drilling rate and caused generations of concern within Hughes' and his competitors' engineering organizations.
Creative and laborious efforts ensued for decades to solve the problem of bits "balling up" in the softer formations, as reflected in the prior art patents. Impressive improvements resulted, including a bit with interfifting or intermeshing teeth in which circumferential rows of teeth on one cutter rotate through opposed circumferential grooves, and between rows of teeth, on another cutter. It provided open spaces on both sides of the inner row teeth and on the inside of the heel teeth. Material generated between the teeth was displaced into the open grooves, which were cleaned by the intermeshing rows of teeth. It was said, and demonstrated during drilling, " . . . the teeth will act to clear each other of adhering material." (Scott, U.S. Pat. No. 1,480,014, "Self-Cleaning Roller Drill," Jan. 8, 1924.) This invention led to a two-cone bit made bye " . . . cutting the teeth in circumferential rows spaced widely apart . . . " This bit included " . . . a series of long sharp chisels which do not dull for long period." The cutters were true rolling cones with intermeshing rows of teeth, and one cutter lacked a heel row. The self-cleaning effect of intermeshing thus extended across the entire bit, a feature that would resist the tendency of the teeth becoming balled up in soft formations. (Scott U.S. Pat. No. 1,647,753, "Drill Cutter," Nov. 1, 1927.)
Interfitting teeth are shown for the first time on a three-cone bit in U.S. Pat. No. 1,983,316, the most significant improvement being the width of the grooves between teeth, which were twice as wide as those on the two-cone structure without increasing uncut bottom. This design also combines narrow interfitting inner row teeth with wide noninterfitting heel rows.
A further improvement in the design is shown in U.S. Pat. No. 2,333,746, in which the longest heel teeth were partially deleted, a feature that decreased balling and enhanced penetration rate. A refinement of the design was the replacement of the narrow inner teeth with fewer wide teeth, which again improved performance in shale drilling.
By now the basic design of the three-cone bit was set (1) all cones had intermeshing inner rows, (2) the first cone had a heel row and a wide space or groove equivalent to the width of two rows between it and the first inner row with intermeshing teeth to keep it clean, (3) a second cone had a heel row and a narrow space or groove equivalent to the width of a single row between it and the first inner heel without intermeshing teeth, and (4) a third cone had a heel and first inner row in a closely spaced, staggered arrangement. A short-coming of this design is the fact that it still leaves a relatively large portion of the cutting structure out of intermesh and subject to balling.
Another technique of cleaning the teeth of cuttings involved flushing drilling fluid or mud directly against the cutters and teeth from nozzles in the bit body. Attention focused on the best pattern of nozzles and the direction of impingement of fluid against the teeth. Here, divergent views appeared, one inventor wanting fluid from the nozzles to " . . . discharge in a direction approximately parallel with the taper of the cone" (Sherman U.S. Pat. No. 2,104,823, "Cutter Flushing Device," Jan. 11, 1938), while another wanted drilling fluid discharged " . . . approximately perpendicular to the base [heel] teeth of the cutter." (Payne, U.S. Pat. No. 2,192,693, "Wash Pipe." Mar. 5, 1940.)
A development concluded after World War II seemed for awhile to solve completely the old and recurrent problem of bit balling. A joint research effort of Humble Oil & Refining Co. and Hughes Tool Co. resulted in the "jet" bit. This bit was designed for use with high-pressure pumps and bits with nozzles (or jets) that pointed high-velocity drilling fluid between the cones and directly against the borehole bottom, with energy seemingly sufficient to quickly disperse shale cuttings, and simultaneously, keep the cutters from balling up because of the resulting highly turbulent flow condition between the cones. This development not only contributed to the reduction of bit balling, but also addressed another important phenomenon which became later known as chip holddown.
Early rolling cutter bits used drilling fluid to clean the cones. Low-velocity fluid was directed onto the cones through relatively large drilled-water-course holes. In 1948, Nolley et al. reported on a new rolling cutter bit in which the drilling fluid was accelerated through nozzle orifices. This high-velocity fluid stream was purposely aimed at the hole bottom, away from the cones, to clean the bottom and to avoid cone erosion. While drilling hard shale in the Mallalieu Field in Mississippi, this bit drilled 68 to 118 percent faster than the previous drilled-water-course bits. This jet bit soon found widespread application. Beilstein et al. documented benefits of jetting hydraulic fluid on the bottom of the borehole. This nozzle orientation, aimed at the hole bottom near the corner of the borehole, more or less equidistant between the cones, became the industry standard. Today, this nozzle arrangement is referred to as a conventional nozzle. Conventional nozzle size and placement was optimized over many years through studies on the effects of hydraulic horsepower, jet impact force and nozzle distance off bottom in a variety of rock types under in-situ stress states.
From almost the beginning, Hughes and his engineers recognized variances between the drilling phenomena experienced under atmospheric condition and those encountered deep in the earth. Rock at the bottom of a borehole is much more difficult to drill than the same rock brought to the surface of the earth. Model-sized drilling simulators showed in the 1950's that removal of cuttings from the borehole bottom is impeded by the formation of a filter cake on the borehole bottom. "Laboratory Study of Effect Of Overburden, Formation And Mud Column Pressures On Drilling Rate Of Permeable Formation," R. A. Cunningham and J. F. Eenick, presented at the 33.sup.rd Annual Fall Meeting of the S.P.E., Houston, Tex., October 508, 1958. While a filter cake formed from drilling mud is beneficial and essential in preventing sloughing of the wall of the hole, it also reduces drilling efficiencies. If there is a large difference between the borehole and formation pressure, also known as overbalance or differential pressure, this layer of mud mixes cuttings and fines from the bottom and forms a strong mesh-like layer between the cutter and the formation, which keeps the cutter teeth from reaching virgin rock. The problem is accentuated in deeper holes since both the mud weights and hydrostatic pressure are inherently higher. One approach to overcome this perplexing problem is the use of ever higher jet velocities in an attempt to blast through the filter cake and dislodge cuttings so they may be flushed through the wellbore to the surface.
The filter cake problem and the balling problem are distinct since filter cake build-up, also known as "bottom balling," occurs mainly at greater depth with weighted muds, while cutting structure balling is more typical at shallow depths in more highly reactive shales. Yet these problems can overlap in the same well since various formations and long distances must be drilled by the same bit. Inventors have not always made clear which of these problems they are addressing, at least not in their patents. However, a successful jet arrangement must deal with both problems; it must clean the cones but also impinge on bottom to overcome bottom balling.
In 1964, Feenstra and Van Leeuwen distinguished between what they termed "bit balling" and "bottom balling." They defined bit balling as powdered rock material which sticks to the teeth of the bit. When the rock material builds up on the cone to a thick layer, it absorbs a portion of the bit weight and prevents the bit teeth from penetrating uncut rock. This is most commonly observed when drilling in sticky shales, but has also been reported to occur in schist. They defined bottom balling as a layer of pulverized rock material covering the borehole bottom, making a plastic and pliable interface between the drill bit and virgin formation, preventing the teeth from cutting virgin rock. This phenomenon has since been shown to occur in a wide variety of rocks. In permeable rocks, this phenomenon is most pronounced and is referred to as chip holddown. Bottom balling also occurs in low-permeability rocks and some shales in which the clay particles tend to stick to each other rather than the bit. Feenstra and Van Leeuwen refer to this as dynamic chip holddown. Bottom balling is a function of borehole pressure and may be the predominant balling mode in shale and mudstone at great depth. Feenstra and Van Leeuwen recommended directing nozzles at cones to combat bit balling and directing nozzles at the borehole bottom to combat bottom balling.
The direction of the jet stream and the area of impact on the cutters and borehole bottom receives periodic attention of inventors. Some interesting, if unsuccessful, approaches are disclosed in the patents. One patent provides a bit that discharges a tangential jet that sweeps into the bottom comer of the hole, follows a radial jet, and includes an upwardly directed jet to better sweep cuttings up the borehole. (Williams, Jr., U.S. Pat. No. 3,144,087, "Drill Bit With Tangential Jet," Aug. 11, 1964.) The cutters have an unusual tooth arrangement, including one with no heel row of teeth, and two of the cutters do not engage the wall of the borehole. One nozzle extends through the center of the cutter and bearing shaft and another exits at the bottom of the "leg" of the bit body, near the corner of the borehole.
There is some advantage to placing the nozzles as close as possible to the bottom of the borehole. (Feenstra, U.S. Pat. No. 3,363,706, "Bit With Extended Jet Nozzles," Jan. 16, 1968.) The prior art also shows examples of efforts to orient the jet stream from the nozzles such that they partially or tangentially strike the cutters and then the borehole bottom at an angle ahead of the cutters. (Childers, et al., U.S. Pat. No. 4,516,642, "Drill Bit Having Angled Nozzles For Improved Bit and Wellbore Cleaning," May 14, 1985.)
In 1984, Slaughter reported on a new bit, which implemented Feenstra and Van Leeuwen's recommendation for bit-balling situations. On this bit, each of the three jets are aimed such that they skim the leading edge of the cone and then impinged on the bottom. Slaughter reported an increase in ROP of up to 27% over convention nozzle bits in field tests. In 1992, Moffitt et al. describe tests in which a variety of nozzle targets in the neighborhood of Slaughter's original directed nozzle were evaluated. A more optimum nozzle target was selected and developed which yielded up to 50% increase in ROP over convention bit nozzles in field applications.
A more recent approach to the problem of bit balling is disclosed in the patent to Isbell and Pessier, U.S. Pat. No. 4,984,643, "Anti-Balling Earth-Boring Bit," Jan. 15, 1991. Here, a nozzle directs a jet stream of drilling fluid with a high-velocity core past the cone and inserts of adjacent cutters to the borehole bottom to break up the filter cake, while a lower velocity skirt strikes the material packed between the inserts of adjacent cones. The high-velocity core passes equidistant between a pair of cutters, and the fluid within the skirt engages each cutter in equal amounts. While significant improvement was noted in reducing bit and bottom balling, the problem persists under some drilling conditions.
In spite of the extensive efforts of inventors laboring in the rock bit art since 1909, including those of the earliest, Howard R. Hughes, the ancient problem of rock bits "balling up" persists. The solutions of the past prevent balling in many drilling environments, and the bit that balls up so badly that the cutters will no longer turn is a species of the problem that has all but completely disappeared. Now, the problem is much more subtle and often escapes detection. It only occurs in the downhole environment and thus is largely unappreciated as a cause of poor drilling performance in the field. Simulation has allowed duplication of that environment and thus led to substantial refinements and improvements of earlier designs.
There are two main bit nozzle classifications. In the first classification are bits in which a conventional nozzle impinges the fluid stream directly on the borehole bottom. The second classification includes bits with nozzles aimed such that they strike some portion of the cone, to clean it, before they strike the borehole bottom, known as "directed nozzles." There are differences in performance between bits with conventional nozzles versus bits with directed nozzles in bit and bottom balling applications. Bits with conventional nozzles are superior in bottom-balling applications, and directed nozzle bits are superior in bit-balling applications.
The nozzle orientation strategy of one type of directed nozzle bits is closely bound up with bit geometry features that result from cone "offset." Some bit manufacturers refer to this same feature as cone "skew angle." The axis of cone bearings of soft formation bits typically does not pass through the center of the borehole. It is offset in the direction of rotation. Because of cone offset, the gage cutting elements of a cone cut gage only on the leading side of the cone. On the trailing side of the cone, the gage cutting elements move away from the gage, creating a "bit offset space" between them and the hole wall.
Compared to a conventional nozzle, the nozzle orifice of this type of directed nozzle is moved circumferentially outward toward the wall of the hole and radially toward the trailing side of the adjacent cone. The fluid stream exits the nozzle at a point closer to the wall, and is oriented more vertically and travels more parallel to the wall than either the conventional nozzle or the other directed nozzle bits. The fluid stream is aimed at the bit offset space. The core of the nozzle skims the cone gage surface, cleaning the gage-cutting elements. It passes through the bit offset space, between the cone and the hole wall, and impinges the borehole at the intersection of the hole wall and hole bottom. After impinging In the corner of the borehole, the borehole wall directs the fluid inward, where it flows through the Interstices of the gage-cutting teeth and over the surface of the cone.
In field applications where bit balling is dominant, bits with directed nozzles typically outperform bits with conventional nozzles. However, in areas where bit balling is not dominant, bits with conventional nozzles often drill faster than directed nozzle bits.
The fact that directed nozzles excel in bit-balling applications and conventional nozzles excel in bottom-balling applications presented opportunities to improve performance by correct selection of nozzle arrangement for a given field application. A hybrid nozzle arrangement was developed which, it was hoped, would allow the bit to clean optimally in either type of balling. A bit which had one conventional nozzle and two directed nozzles was tried. This was implemented on a cutting structure which has a heel arrangement on one cone called an anti-balling heel. The term "heel" refers to the outer-most row of teeth on the face of the bit, which cuts gage. The heel row on this one cone experiences less balling than standard heels. Therefore, the conventional nozzle was placed on this leg, while the directed nozzles were aimed at the other two legs, which had standard heel rows. It was hoped that the one conventional nozzle would be sufficient to clean the bottom, in bottom-balling applications, and the two directed nozzles would be sufficient to clean the cones in bit-balling applications and as a result, this bit would approach optimal performance in both environments.
The rate of penetration ("ROP") of the hybrid bit in these tests was faster than the directed nozzle bit in Catoosa shale, indicating that the one conventional nozzle was effecting some cleaning of the bottom. However, the hybrid bit never achieved an ROP in Catoosa as high as the bit with three conventional nozzles, indicating that the one nozzle aimed at bottom did not clean as efficiently as the three nozzles of a conventional bit. The hybrid bit was slower in Mancos shale than the bit with three directed nozzles. An increase in bit balling was observed on the cone adjacent to the conventional nozzle, especially on the inner rows.
Thus, the performance of this hybrid bit fell in between the directed nozzle bits and conventional nozzle bits. It was more of a compromise in each environment than an optimal solution in each.
The selection of an appropriate nozzle arrangement for any given field application depends on whether bit balling or bottom balling is the predominant in that application. Many studies have been conducted in an effort to determine what shale and mud properties cause balling. No consensus has yet been reached and it is not possible to predict whether a shale will cause balling or not. It is even less possible to distinguish a priori whether a particular shale and mud combination will cause bit balling or bottom balling.
However, it is possible to distinguish bit and bottom balling in practice through a drill-off test because bit balling and bottom balling have different ROP responses to increasing bit weight. When bit-balling tendencies are present, increasing weight on bit will result in increasing ROP only to a point, referred to as the flounder point. At this point, cuttings pack in between the teeth and absorb bit weight, preventing the teeth from cutting virgin formation. Increasing bit weight after the flounder point has been reached does not increase ROP. However, when bottom balling occurs, a flounder point is not observed and ROP continues to increase with increasing bit weight. The reason for the difference in ROP response to weight is that in bottom-balling situations, balled material can extrude into the spaces between the cones; however, in a bit-balling situation, the compacted material is confined in spaces between the teeth and borehole wall and bottom and cannot extrude.
Thus, a bit with directed nozzles is the best choice for drilling applications which exhibit a flounder point, and a bit with conventional nozzles is the best choice for drilling applications which do not exhibit a flounder point.
Cone erosion is another factor that dictates nozzle choice. Since bits with directed nozzles expend a portion of their hydraulic energy on the cones, they may erode the steel bodies of the cones, eventually leading to loss of carbide or steel teeth. Circumstances which cause cone erosion include a high sand content in the mud and high hydraulic horsepower.
When drilling in areas with a high sand content, the abrasive sand particles may cause excessive cone erosion on directed nozzle bits. However, areas with high sand content are typically not areas in which bit balling is prevalent. Thus, the best choice of bit for areas with a high sand content is the conventional nozzle bit. In these areas, directed nozzles are not needed to clean the cones and, in fact, directed nozzles may be a liability due to cone erosion.
It has been observed that the benefit of directed nozzle bits over conventional nozzle bits diminishes with increasing HSI. Furthermore, a high HSI can lead to cone erosion on directed nozzle bits. These two facts make the conventional nozzle bit a better choice than a directed nozzle bit at high HSI levels. Cone erosion can become a problem at or above 150 horsepower per cone in areas where sand content is low. Where sand content is high, erosion may occur as low as 80 horsepower per cone. Cone erosion may be particularly critical when a blank nozzle is run in a bit since the horsepower levels of the jets in the two remaining nozzles may exceed these limits. If a directed nozzle bit needs to be run and cone erosion is likely to occur, the cones may be coated with a carbide coating which eliminates cone erosion due to fluid impact.
Laboratory tests of bits in situations with bit balling and bottom balling have shown that there are different optimal nozzle configurations for each of these situations. Bits with directed nozzles have higher ROP in bit-balling situations. Bits with conventional nozzles have higher ROP in bottom-balling situations. These results are consistent with field observations.
In field applications, the presence of a flounder point is indicative of bit balling. In these cases, bits with directed nozzles should be used. When a flounder point is not observed, bits with conventional nozzles should be used.
Potential cone erosion is also a factor to be considered in deciding between bits with directed nozzles and conventional nozzles. If sand content is high, bit balling is most likely not prevalent and bits with conventional nozzles should be used. When hydraulic horsepower per cone exceeds certain limits, erosion may occur. If cone erosion is excessive, erosion-resistant cone coatings may be used.
What has heretofore been lacking is a bit which can flexibly accept directed and conventional nozzles interchangeably or simultaneously so that when a given situation of bit or bottom balling is expected or encountered, a bit can be easily configured prior to delivery to a field site or even by personnel at the rig site so that maximum ROP is obtained. This is one of the objects of the present invention.
Patents and literature describes various nozzle configurations, including U.S. Pat. Nos. 5,096,005; 4,516,642; 4,546,8347; 4,558,754; 4,582,149; 4,878,548; 4,794,995; 4,776,412, and 1,388,490; and Feenstra, R., and J. J. M. Van Leeuwen, "Full-Scale Experiments on Jets in Impermeable Rock Drilling," Journal of Petroleum Technology, Mar. 1964, pp. 329-336.
Recently, the Hughes Christensen division of Baker Hughes has introduced the HydraBoss line of bits where the nozzles are moved adjacent one of the cones, and their central axes are oriented in such a way that the stream from such nozzles passes adjacent the rolling cone to minimize the effect of bit balling.
A difficulty that is encountered is that when bits are manufactured, it is not known in what service they will ultimately be employed and, therefore, the past designs, which have nozzle systems oriented toward addressing either one of the two problems of bit balling or bottom balling, can have difficulty in rate of penetration when the other problem occurs and the nozzles are not oriented to address it. Accordingly, one of the objects of the present invention is to provide a bit design primarily for a roller cone bit where the design allows for flexibility in orientation of one or more of the nozzles to address, in a given bit, not only one of the two issues of bit balling or bottom balling, but both. Additionally, this flexibility is to be provided in the manner that allows the most efficient use of the fluid energy available for either addressing the bit-balling or bottom-balling situation. Another objective of the present invention is to allow, between each pair of roller cones, the ability to address one or both of these problems in an individual bit.
One of the solutions that has been attempted in the past with limited success is the use of a tilted nozzle, as shown in FIG. 2. The tilted nozzle was employed to address the bit-balling problem where the standard nozzle location was being used for installation of the tilted nozzle shown in FIG. 2. The idea was to address the bit-balling situation without modifying the existing bit body. The problem which arose occurred due to the placement of the standard nozzle opening between two adjacent cones, which traditionally functioned to accept conventional nozzles oriented to deal with bottom balling. To address the bottom-balling situation, the conventional nozzle location was approximately mid-way between two adjacent roller cones. The idea in the past was to take the tilted nozzle, which has a nozzle bore which, at its outlet end, is misaligned with the center axis of the nozzle body, and turn the nozzle in such a manner so as to point the stream toward the cone to address the bit-balling situation. A disadvantage of this design was that a greater distance had to be traversed by the nozzle stream to reach the cone area from the standard nozzle mount in the bit body, where the nozzle mount is oriented for addressing bottom-balling situations. Thus, the incrementally greater distance with an offset bore in the nozzle, as indicated in FIG. 2, reduced the available energy in the nozzle stream to remove cuttings, as well as dissipated the fluid energy since the fluid was forced to turn within the nozzle prior to exiting into the borehole for fulfilling its cleaning function. The tilted nozzle gave the operator some flexibility in adapting a bit for a particular function. In using the tilted nozzle, the customer could select not only different orifice sizes, but also the direction of the flow could be changed. However, the optimum in addressing the bit- and/or bottom-balling situations could not be achieved with the tilted nozzle design because of the drawbacks of its physical positioning, as well as the attendant energy losses due to directional changes within the nozzle body. Accordingly, it is another object of the present invention to allow nozzle mounting systems that can convert in a given bit to address bit- or bottom-balling situations, while at the same time optimizing the energy and placement of the fluid stream so as to more efficiently accomplish one or the other functions from a given nozzle. These and other objectives of the present invention will become more apparent to those of ordinary skill in the art from a review of the detailed description of the preferred embodiment below.